Maintaining substantially constant pressure differential downstream of a hydrogenating reactor



R. S. BAXTER ET AL May 9, 1961 2,983,675 LY CONSTANT PRESSURE DIFFEREMAINTAINING SUBSTANTIAL NTIAL DOWN-STREAM OF A HYDROGENATING REACTOR 2Sheets-Sheet 1 Filed July 5. 1957 May 9, 1961 R. s. BAXTER ET AL2,983,675 RENTIAL MAINTAINING SUBSTANTIALLY CONSTANT PRESSURE DIF'FEDOWNSTREAM OF A HYDROGENATING REACTOR 2 Sheets-Sheet 2 Filed July 5,1957 United States Patent MAINTAINING SUBSTANTIALLY CONSTANT PRESSUREDIFFERENTIAL DOWNSTREAM OF A HYDROGENTING REACTOR Richard S. Baxter,Detroit, and Curliss F. Miller, Trenton, Mich., assignors to SoconyMobil Oil Company, Inc., a corporation of New York Filed July 5,1951,ser'. No. 670,136

s Claims. (Cl. 20s-212) The present linvention relates to the chokingand the `corroding of piping and valves downstream of hydrogenatingreactors treating hydrocarbon mixtures containing nitrogen and chlorinecompouunds and, more particuflarly, to the choking and corroding ofpiping, valves and ferrous -a'lloys downstream of a naphtha pretreateremployed for the removal of sulfur as hydrogen sulfide from the naphthafeed to a reformer.

Before discussing the locations at which choking and corroding of pipingand valves occur downstream of a reactor, employed in hydrogenatinghydrocarbons admixed withorganic sulfur, nitrogen and chlorine com-Lpounds and the means by which such choking and corrosion of ferrouspiping and valves can be reduced if not eliminated, it is believeddesirable to discuss two flow sheets illustrative of the operations inwhich the aforementioned difficulties arise.

` t Illustrative of the operations beset by choking and corroding ofpiping downstream of a hydrogenating reactor treating a mixture offhydrocarbons containing nitrogen land chlorine, is the pretreatment ofnaphtha to remove sulfur and nitrogen prior to reforming the pretreatednaphtha.

Figure l of the drawings is a highly schematic flow `sheet showing theflow of liquids, vapors and gases in the pretreatment of naphtha priorto reforming in which the efiuent from the hydrogenating reactor is heatexchanged first with the feed naphtha, then with bottoms of a splitterand again with the feed naphtha before being 'introduced exchanged firstwith the feed naphtha, then with the bot-` toms of a stripper, and againwith the feed naphtha before being introduced into a flash drum or othermeans for separating hydrocarbons having four or more carbon atoms permolecule from hydrogen, hydrogen sulfide,

. and hydrocarbons having less than four carbon atoms per molecule.

The dow` sheets Figures 1 and 2 are notlimiting but merely illustrativeof the localities at which plugging and corrosion of piping occursdownstream of a reactor in which hydrocarbons contaminated with nitrogenand chlorine compounds are hydrogenated. In general, choking of pipingoccurs at that point in the piping downstream of the hydrogenatingreactor at which the reactor 1 efliuent is first cooled to about 450 F.or below 450 F.

The dow sheet of Figure 1 is illustrative of a unit in i which heavynaphtha is drawn by pump `1 through pipe y 2 from a source not shown anddischarged through pipe 3 to the top of absorber 4. Pump 5 draws lightnaphtha through pipe 6 from a source not shown and discharges rice thelight naphtha into pipe 7 through which the light naphtha flows toabsorber 4.

LIn absorber 4 the naphtha to be treated, i.e., the feed naphtha fiowsdownwardly countercurrently to the upwardly flowing gases flowing fromthe liquid-gas separator 29 .through line 30 and from the reforming unit(not shown) through Iline 31. The contact of the naphtha feed with thegases removes 4a major portion of the entrained hydrocarbons having fouror more carbon atoms per molecule from the gases providing an enrichednaphtha.

The enriched naphtha is drawn from absorber 4 by pump 9 through line 10.Pump 9 discharges the enriched naphtha into pipe 11 at slightly abovethe pressure of decontaminating or hydrogenating reactor 19. Theenriched naphtha flows along pipe 1f1 to heat exchanger 12 where it isin indirect heat exchange relation with efiluent from reactor 19 ashereinafter described. From heat exchanger 12 the enriched naphtha flowsthrough pipe 13 to heat exchanger 14 where the enriched naphtha is inindirect heat exchange relation with effluent from reactor 19. From heatexchanger 14 the enriched naphtha ows through pipe 15 to coils 16 infurnace 17.

In furnace 17 the enriched naphtha is heated to a reaction temperatureof about 600I to about 800 F. for sulfur removal by hydrogenation of theorganic sulfur compounds. From coil 16 the heated enriched naphtha owsthrough pipe 18 to reactor 19. Hydrogen-rich g-as flowing from areformer unit (not shown) o-r other source of gas containing at least 25percent and preferably at least 60 percent hydrogen is mixed with theheated enriched naphtha in the proportion of about 250 to about 500standard cubic feet (s.c.f.) per barrel.

The heated enriched naphtha and hydrogen-containing gas flow downwardlythrough reactor 19 in contact with a (preferably) sulfur-insensitivehydrogenating desulfurization catalyst, e.g., a mixture of oxides ofcobalt and molybdenum on alumina. Contact with such a. catalystdecomposes the organic sulfur compounds to hydrocarbons and hydrogensulfide. Organic nitrogen compounds are decomposed to the hydrocarbonand ammonia. Organic chlorine compounds are decomposed to thehydrocarbon yand hydrogen chloride. The reactor effluent comprisinghydrogen, hydrocarbons, ammonia, hydrogen sulfide and hydrogen chlorideflows from reactor 19 through pipe 20 to heat exchanger 14. 'Ihencethrough pipe Z1 to heat exchanger 22 where the reactor euent is inindirect heat exchange relation with condensate from liquid-gasseparator 29 flowing through pipe 34.

From heat exchanger 22 the reactor effluent dow-s through pipe 23 toheat exchanger 12; where it is in indirect heat exchange relation withenriched naphtha flowing through 'pipe 11. From heat exchanger `12 thereactor eiiluent flows through pipe 24 to condenser 25. From condenser25 the reactor efliuent cooled to a temperature at which hydrocarbonshaving four or more carbon yatoms per molecule are condensed ows toliquidgas separator Z9.

In liquid-gas separator 29 the unconflensed hydrogen, hydrogen sulfide,hydrocarbons having less than four carbon atoms per molecule and othernon-condensable gases are vented through line 30 and dow to absorber 4.The condensed hydrocarbons are drawn from separator 29 through pipe 2.7by pump 28 and discharged into pipe 32. The condensate 4from separator29 ows through pipe 32 to heat exchanger 33 where the condensate is in tindirect heat exchange relation with the bottoms of splitter 36, thefeed to the reformer unit (not shown). From heat exchanger 33 theseparator condensate flows through pipe 34 to heat exchanger 22 wherethe separator condensate is in indirect heat exchange relation withreactor eflluent flowing through pipe 21. From heat ex- 3 changer 22 the@separator condensate flows through pipe 35 to splitter 36.

In splitter `36 an overhead is taken through pipe 37 to condenser 38.From condenser 3S the splitter 'overhead flows through pipe 39 toaccumulator 40. In accumulator 40 the components of the splitteroverhead boiling below butane :are vented to refinery fuel system orrecovery through line 41. The components of the splitter overheadyboiling above butane flow from the accumulator through pipe 42 and inpart are purnped to splitter 36 through pipe 43 by prunp 44 and thebalance is pumped through pipe 45 by pump 46 to the light straight runstabilizer (not shown).

In the ow sheet designated Figure 2 a stripper is substituted for thesplitter of Figure 1. Thus naphtha feed is drawn through pipe 101 bypump 102 from a source not shown and discharged into pipe 103, The feednaphtha flows partially through pipe 104 and partially through pipe 105into absorber 106 in which it contacts in countercurrent flow gasflowing from stripper 136 and gas-liquid `separatori' 1127. Fromabsorber 106 the enriched naphtha is drawn through pipe 107 by pump y108which ldischarges 4into pipe 109.

The enriched naphtha llows -alon-g pipe 1109 to heat exchanger 110 whereit is in indirect heat exchange relation with the efuent lfromhydrogenating reactor 119 flowing through pipe 120. From heat exchanger110 the enriched naphtha flows through pipe 1.11 to 'heat exchanger 112Where the enriched naphtha is in indirect heat 'exchange relation withreactor effluent owing through pipe 120.

From heat exchanger 1f12 the enriched naphth-a Hows through pipe 113 tocoils `,114 in furnace 115. In furnace 11S the enriched naphtha -isheated to reaction temperature which for hydrodesulfurization is about6009 to about 800 F. From coils 114 the heated enriched naphtha iiowsthrough Apipe 116 to pipe 118. Hydrogenrich -gas flowing `from lareformer unit (not shown)' through pipe-117 (when `desirable a portionor all of the gas flowing from stripper 136 through line 141 can bediverted through line 146 and mixed with the hydrogenrich gas flowingthrough line 1-17) is mixed with the hot enriched naphtha in pipe 118 atthe rate of about 25() to about 650 s.c.if. per barrel of enrichednapfhtha.

The enriched naphtha and hydrogen-containing gas ow downwardly throughhydrogenating reactor 119 in contact with a hydrogenating desulfurizingcatalyst such as 'a mixture `of oxides of cobalt and molybdenumsupported on an alumina carrier. In the hydrogenating reactor hydrogensulde, ammonia and hydrogen-chloride are produced. These gases, togetherwith thenaphtha feed andthe excess hydrogen-containing gas, designatedreactor euent, ow through pipe 120 to heat exchanger 112 discussed'hereinbefore From heat exchanger 112 the reactor eiuent flows throughpipe 121 to heat exchanger `122 where the Vreactor eliluent is inindirect heat exchange with the condensate from gas-liquid separator 127Aiiowing `through pipe 137 from heat exchanger 132.

From heat exchanger 122 the reactor effluent flows through pipe 123 toheat exchanger 110 where it is in indirect heat exchange relation withenriched naphtha as discussed hereinbefore. From heat exchanger 1110 thereactor eluent liows through pipe 124 to cooler 1125 where the reactorefluent is cooled to a temperature at which the C4 and higherhydrocarbons `are condensed.

The cooled reactor eiuent ilo-ws from cooler- 125 through pipe 126 togas-liquid separator 127. Thegaseous portion of the cooled reactorefuent, i.e., hydrogen,

hydrogen sullide, hydrocarbons boiling Ibelow butane and othernon-condensable gases is vented from separator pipe 131 through whichthe condensate ows to heat exchanger `132. In heat exchanger 132 thecondensate is in indirect heat exchange relation with the bottoms ofstripper 136 flowing through pipe 133.

From heat exchanger 132 the condensate flows through pipe 137 to Iheatexchanger 122 where the condensate is in indirect heat exchange relationwith the total reactor efliuent flowing through pipe 121.V From heatexchanger 122 the condensate ows through pipe 138 to stripper 136. l

To `assist in stripping gaseous components of the reactor effluent fromthe condensate a portion of `the hydrogenrich gas flowing through line139 to line 1f17 is diverted tokstripper 136 through `line 140.

All overhead comprising hydrogen, hydrogen sulfide and hydrocarbonshaving less than four carbon atoms per molecule is taken through line-141 to absorber 106 or to reactor 119 as discussed hereinbefore.

A bottoms is drawn from Astripper 136 through pipe 135 by pump 134 andpumped through pipe 133,V heat exchanger 132 and pipe 142 to cooler 143.From cooler 143 the stripper bottom ows through pipe 144 as -relformerfeed to a reforming unit (not shown),

In light of the `foregoing discussion of the flow 4sheets Figures 1 and2 the problems of the obstruction ofpping and corrosion of ferrousalloys downstream of the hydrogen-ating reactor can be `discusssed withgreater clarity.

In a unit employing the equipment and heat exchanger train illustratedby the flow sheet Figure 2 a pressure differential of 10 p.s.i.increased to 125 p.s.i. across heat exchanger 110 (Figure 2) after threemonths of operation. AThe unit was shut down and approximately 750pounds of deposits removed. When the Vunit was put on stream thepressure differential across heat exchanger 110 (Figure 2) was 40 p.s.i.Following a second shutdown and removal of deposits the pressure dropacross heat exchanger 110 decreased to 10 p.s.i. Within one week afterputting the unit back on stream the pressure drop across heat exchanger110 had increased to 25 p.s.`i. It is to be noted that the temperatureof the total reactor effluent is reduced to below 450 F. in heatexchanger 127 through line 128-an'dpows therethrough to absorber v 106as discussed hereinbefore. n n

The condensed reactor effluent hows from separator 12,7 through pipe129`t0 the suction side of pump i130.

Pump 130 `discharges the reactor efuent condensate into In a unitemploying the equipment and heat exchanger train illustrated in Figure 1corrosion was observed in the splitter overhead pumps after only sixtydaysoperation. Heavy deposits also had built up in the piping connectingthese pumps as Well as in heat exchangers 2 and 12.

.It was found that these deposits were saline in nature and `comprisedpredominantly ammonium chloride. Consequently, it was not surprising toVfind that these deposits can be removed by flushing the criticalportions of the system with water. However, the indiscriminate use ofwater produces other `equally troublesome difliculties.

Probably the most important limiting factor in theuse of Water toeliminate or at least markedly reduce the amount of lwater-soluble saltsdeposited in the equipment, hea-t exchangers, piping and the likedownstream of a hydrogenating reactor treating a hydrocarbon feedcontaining nitrogen compounds and chlorine compounds decomposable underreactor conditions is the water content ofthe effluent from thedecontaminating unit, i.e., the decontaminated feed to the reformerunit. Many platinum-type catalysts are water-sensitive. The presence ofmore than a limiting amount of Water in the feed to platinum-typereforming catalyst results in the loss of activity. Thus, themanufacturer of one kplatinum-type catalyst recommends that the amountof water in the feed to a reforming unit in which that platinum-typecatalyst is used not exceed 40 p.p.m. Many operators, however, limit theconcentration of water in the feed to a reforming unit employing thatparticular platinum-type catalyst to a maximum of 20 p.p.m.

A further difhculty'accompanying the use `of indiscriminate amounts ofWater to reduce or eliminate the deposi'tofwater-solubie salts in thesystem downstream of a decontaminating reactor is the result ofsaturation of the vaporous or gaseous portion of the eflluentwith theexcess water. 'Thewater introduced into the gaseous portionofatheellluent` returns to the absorber and destroys the operationalbalance. Water' carried over mechanicallyjq- `the fractionating system`interposed between th'e liqnf'dfgals separator of the decontaminatingunit and the entrance to the reforming unit gathers in the trays of thefractionating unit and destroys the fractionation balance of `thetowers. Thus, it becomes evident that there are critical limits to theamount of water which can be introduced into the `system downstream ofthe decontaminating reactor when removal of the salt deposits is to beaccomplished without taking the unit off-stream.

The lower critical limit is the minimum amount of water required toremove the deposits of water-soluble salt as a solution which will notbe supersaturated at the temperatures to which it is subjected beforebeing withdrawn from the system. The upper critical limit is the maximumamount of water which can be used without disrupting the bal-ance of thefractionating operations downstream of the reactor.

Thus, in a refinery operating a decontaminating unit such as illustratedin Figure l, it was found that continuous injection of water at anypoint between reactor 19 and heat exchanger 22 at the rate of about 1.5gallons per minute (g.p.m.) or at the rate of about 1.75 to about 2.0gallons perbarrel of naphtha throughout would keep the heat exchangers22 and 12 substantially free from water-soluble salt deposits. The pointselected for injection of water is one where the temperature of theetiiuent is higher than about 450 F.

It is preferred to inject hot water, i.e., water having a temperature ofat least about 180 F. However, the injection of steam is notsatisfactory since the salt deposit must be'dissolved in and carried insolution in the liquid water. Hence, the maximum temperature of thewater injected is that at which the injected water will remain liquid atthe pressure existing downstream of the point of injection. It has beenfound that a satisfactory source of water for injection is boiler feedwater having a temperature of about 220 F. under a pressure of about 600p.s.i.g.

It has been found that when hot water is injected at the rate of about1.5 gpm. or about 0.25 gallons per barrel of feed to the decontaminatingreactor at a point such as 47 (Figure 1) or 146 (Figure 2) practicallyall of the water can be drawn-off at the gas-liquid separator 29(Figure 1) or 12,7 (Figure 2) through pipes 48 and 145 respectively.Thus, while injecting hot water at the rate of 10.5 g.p.m. into thereactor eluent stream at 146 water was drawn from lthe flash drum at 145at the rate of 9 g.p.m. No water appeared in the stripper bottoms andonly minor amounts of water appeared in the absorber. The minor amountsof water which appeared in the absorber did not interfere with thesteady operating conditions of the unit.

When injecting hot water, c g., boiler feed water under 600 p.s.i.g. ata temperature of 220 F. into the total effluent at the rate of 10.5gpm., i.e., at the rate of 0.75 gallon per barrel of feed to thedecontaminating reactor no difficulties arose in the operation of eitherthe stripper or the absorber. However, in another plant the injection ofhot water at the rate -in excess of 0.5 gpm. was found to result in anexcessive amount of water in the -feed to the reforming unit. That is tosay, when water was injected at the rate of l gpm., i.e., 0.16 gallonper barrel of feed to the decontaminating reactor it was found that thewater in the charge to the reformer was present in a concentration of 84p.p.m. greatly in excess of the maximum recommended by the catalystmanufacturer. Accordingly, it is necessary to inject hot waterdownstream of the decontaminating reactor and upstream of the point atwhich the temperature of the reactor eiiueht first reaches 450 at a ratenot exceed; ing about .4 gallon per barrel of feed to thedecontaminating reactorand preferably about .25 to about .35 gallon perbarrel of feed to the aforesaid reactor. The minimum amount of waterinjected into the eiuent 4stream downstream of the decontaminatingreactor is the minimum amount of water in the liquid state under theconditions of temperature and pressure existing in the system downstreamof the reactor required to mainf tain a substantially' constant pressuredifferential between a;point in Ithe system upstream of the point atwhich the temperature of the reactor efliuent stream first is reduced.to about 4,50"J F., hereinafter designated the 450 point and a pointdownstream of the 450 point. The maximum amount of water to be injectedis that amount of which at least percent can be drawn-off upstream offractionating equipment.

While the injection of water such as boiler-feed water or other waterhaving a pH of 7 is satisfactory for the maintenance of substantiallyconstant pressure differential across heat exchangers yand the likedownstream of the point at which the temperature of the reactor efduentfirst is lowered to about 450 F., corrosion of ferrous metals in contactwith the reactor eiuent is not eliminated or reduced to a negligiblerate. Accordingly, it is preferred to inject Water containing a buier oran alkaline agent and having a pH of at least 8 in suilicient amount tomaintain the pH of the system at about pH7 tto 7.2. The material whichaccomplishes the purpose while introducing the fewest difliculties isammonia. Accordingly, it is referred to inject solutions of ammoniahaving an ammonia concentration such as to produce aqueous solutions ofabout 26 Baume at the rate of about l to -about 2.5 gallons for 10,000barrels of oil per day.

While water can be injected continuously to remove water-soluble saltsdeposited downstream of the 450 point, it is preferred to inject thewater intermittently. Intermittent injection of water into the systemreduces the possibility of injected water being carried over into thefractionating system. To ensure the presence of water in the liquidphase downstream of the 450 point, it is necessary to inject water at arate greater than that at which it can be vaporized under the conditionsof temperature and pressure downstream of the 450 point and rejectedwith the absorber off-gas. Intermittent injection of water rather thancontinuous injection of water is preferred since intermittent injectionof water allows the recycled water (in the gas-liquid separator gas) tobe rejected during the period when water is not injected. The injectionpreferably is repeated only after the gaseous phase is substantiallyfree of water from the previous injection. Intermittent injection ofwater results in the rejection of recycled water without resort tiointerfacial cont-rol systems and without the danger of disruptingfractionating tower operation because of water levels on the towertrays. The injection of water preferably is effected within a period offrom about 10 minutes to about ltwo hours.

We claim:

l. A method for pretreating a reformer feed stock containing sulfur,nitrogen, and chlorine compounds as contaminants which comprisesreacting said feed stock with hydrogen under .desulfurizing conditionsthereby producing an eilluent stream comprising hydrocarbons, hydrogenand water-soluble material derived from said contaminents, injecting hotwater into said effluent stream while the said stream is at atemperature in excess of about 450 F. and under a pressure suicent tomaintain said water in the liquid phase, cooling said mixed stream ofefiluent and water to a temperature at which C4 and higher hydrocarbonsare condensed, separating from said cooled mixed stream, (a) a gaseousfraction, (b) an aqueous fraction containing said water soluble materialin solution and (c) a liquid hydrocarbon fraction comprising C4 andhigher hydrocarbons.

2. The method as set forth in claim 1 in which the sep# arated liquidhydrocarbon fraction contains not more than 15% yof the injected Water.A 3. The: method as set forth in ciaimfl in which the liquid hydrocarbonfraction is fractionated to provide a reformer feed stock containing notmore than 40 p.p.m.

water. y, i Y

4. The method as set forth in claim 1 in which said hot Water isinjected into Vsaid eluent stream intermitftently for periods of fromabout ten minutes to about two hours at a temperature of about 180 F.and said injectemperature of fat least 180f1 F.

References Cited in the file of this "patent" UNITED STATES PATENTS2,529,790 Waddill Nov. 14, 1950 2,758,064 Haensel a Aug.. 7, 19562,785,120

Mealf I 'Mar. 1?.,4 1957 Bolinger et a1. June 20, 1939

1. A METHOD FOR PRETREATING A REFORMER FEED STOCK CONTAINING SULFUR,NITROGEN, AND CHLORINE COMPOUNDS AS CONTAMINANTS WHICH COMPRISESREACTING SAID FEED STOCK WITH HYDROGEN UNDER DESULFURIZING CONDITIONSTHEREBY PRODUCING AN EFFLUENT STREAM COMPRISING HYDROCARBONS, HYDROGENAND WATER-SOLUBLE MATERIAL DERIVED FROM SAID CONTAMINENTS, INJECTING HOTWATER INTO SAID EFFLUENT STREAM WHILE THE SAID STREAM IS AT ATEMPERATURE IN EXCESS OF ABOUT 450*F. AND UNDER A PRESSURE SUFFICIENT TOMAINTAIN SAID WATER IN THE LIQUID PHASE, COOLING SAID MIXED STREAM OFEFFLUENT AND WATER TO A TEMPERATURE AT WHICH C4 AND HIGHER HYDROCARBONSARE CONDENSED, SEPARATING FROM SAID COOLED MIXED STREAM, (A) A GASEOUSFRACTION, (B) AN AQUEOUS FRACTION CONTAINING SAID WATER SOLUBLE MATERIALIN SOLUTION AND (C) A LIQUID HYDROCARBON FRACTION COMPRISING C4 ANDHIGHER HYDROCARBONS.